One of the main objectives of primary cementing is to provide zonal isolation by preventing the percolation of gas through a cemented annulus, which could result in channels in the cement sheath. Gas channeling, once established, has proven to be extremely difficult and costly to repair.

The most current theory used to explain gas migration is the early gelation of the cement slurry, which leads to a decrease of hydrostatic pressure within the cement annulus. Over the years, various models have been developed, most of them revolve around the concepts of static gel strength (SGS), critical static gel strength, (CSGS), and transition time. Unfortunately, these approaches have failed to accurately predict gas migration. One of the main reasons for this failure is that these approaches are based on fluid-mechanics theories, and do not take into account the cement phase changes during hydration (fluid to solid) besides their effects on the SGS. Additionally, most models do not take into account the true mechanisms at the origin of gas percolation: Matrix, chimney, and micro-annulus.

This paper presents the use of a new gas migration model that eliminates these drawbacks, in order to investigate the effect of the cement composition on the cement sheath integrity. This model considers two different stages in the life of the cement sheath (fluid-type and porous-solid type), and is characterized by constitutive laws, which are integrated over the length of the cement column by time to determine if gas migration will occur and what are the mechanisms according to which it would occur. The simulations demonstrate the crucial role that the cement composition has on the state of stresses and pore pressure in the cement sheath, on the opening and closure of micro-annuli and on the vertical displacements of cement sheath during cement early ages. They highlight that an analysis of cement sheath integrity during hydration requires checking a combination of different mechanisms during the life of cement from fluid-type to porous-solid type.

Today's data is tomorrow's oil and gas. Only the data can tell us right or wrong, but not the experience or feel. The real-time logging data conforms to the 6V features of the Big Data (Velocity, Variety, Volume, Veracity, Visualization and Validity). As a result, the drilling operations efficiency is significantly improved by the Big Data mining of real-time logging.

The Big Data mining helps recognize the drilling operations automatically and identify the invisible non-production time (INPT). Firstly, the real-time logging data is acquired by the comprehensive logging unit. Secondly, the drilling operations are recognized by applying restrictions to drilling parameters. Thirdly, the daily time and the total time is breakdown based on the above logging data and operations categories. Finally, the INPT is identified by setting the target value based on the Big Data mining and learning curve.

The savings potential, which is determined by the average and target, is critical to improve the operations efficiency. On one hand, the Normal Distribution is established by setting the specific operation time (such as slips connection time, etc.) to the X-axis and the operation count to the Y-axis. The average and covariance of the Normal Distribution is calculated. On the other hand, the target value is based on the Big Data mining by the Bayesian network model and the total-time learning curve of batch wells. As a result, the real-time drilling efficiency can identify the best-performing operations, crews and rigs. The crew-based operational performance comparisons are effective to identify the best-performing crews and to indicate where best to focus training and crew supervision efforts in the future. And the real-time drilling efficiency can measure the rig performance in order to make INPT visible. At last, the real-time drilling efficiency yields cost and time savings on both deep-water and complex wells. The method is successfully applied to BD gas field in Indonesia which is HTHP and LW oil field in South China Sea which is in deep-water. Application shows the INPT represents about 32%.

The Big Data mining of real-time logging significantly improve the drilling operations efficiency, detect and minimize the INPT. As a result, the Big Data mining yields cost and time savings for tomorrow's market.

Annuli pressure if not controlled and managed may result in uncontrolled release of high-pressure hydrocarbon fluids from reservoir to the surface. This may cause loss of life, damage to environment, and tarnish the reputation of the company. In this paper, two potential pathways for reservoir fluid to reach the surface through annuli have been examined, and recommendations were provided to diagnose and manage annulus pressures within safe operating limits.

Integrated well integrity assessment to diagnose the root-cause of annulus pressure involved using various tools to measure key parameters needed to make an accurate assessment of root-cause of annulus pressure. For example, thermal numerical models and lab tests were conducted to simulate thermal effects in the well and analyze annulus fluid samples, respectively. Furthermore, echometer was used to measure fluid-level in the annuli, whereas logging tools such as spectral noise, high-precision temperature etc. were used to identify source of any reservoir fluid ingress.

Multiple diagnostic, surveillance and management workflows for outer and inner annuli have been developed. Experiences in implementing these workflows for hundreds of wells in the field have been described and lessons learned have been discussed. Special attention has been paid to the cases with confirmed or suspected lost barriers. Appropriate, cost-efficient levels of diagnostics have been selected and employed to ensure safe operations. Decision trees on how to manage wells with annulus pressures have been discussed, in particular related to planning and execution of pressure bleed-offs, annulus top-ups with heavier fluids, etc. Based on decision trees, cost-efficient levels of diagnostics have been selected and employed to ensure safe operations.

This work provides insights on various tools to diagnose and cost-effectively manage the pressure in the annulus by combining the available tools and software. Company-specific annulus pressure management strategies have been developed and successfully employed to safely operate wells with annulus pressure.

The increasing need for completions to be capable of withstanding higher treating pressures, combined with complex well geometries and cementing requirements, led to the development of a new 4 1/2-in. completion system that includes liner systems to facilitate isolation objectives, and upper completion systems to create a monobore conduit. This new monobore completion system is rated for 15,–KSI target surface treating pressures.

Traditionally, cementing and isolation objectives have been achieved using liners and liner hangers capable of deploying those liners and also isolating the target zone. To achieve a monobore completion design, an integral tieback receptacle (TBR) is used to tie the liner back to surface. The integral TBRs currently used are either too short to enable the necessary tubing movement stroke, or rated too low to enable the required treating pressure.

A solution was developed integrating a lower polished bore receptacle (PBR) below the liner hanger that is capable of withstanding the pressure requirements, and using a compression-set anchoring system to anchor a seal assembly inside the PBR. To account for tubing movement and help reduce mechanical loading on the tubing and upper completions components, a PBR is placed above the compression-set anchor.

This arrangement enables the liner hanger systems to be isolated from treating pressures, which helps remediate limitations associated with traditional completion systems. Considering that the liner hanger is isolated from tubing treating pressures and that the compression-set anchor does not isolate annular pressure, the TBR on the liner hanger is pressure-balanced, no longer exceeding the pressure limit. Furthermore, tubing-casing annulus (TCA) pressure that is normally applied during stimulation can now support the liner hanger and lower tieback seals.

A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and to avoid colliding with other offset wells. The selection of the wellbore survey tools within the survey program are limited to the current accuracy available to the industry. A newly developed wellbore survey technique has proven to have superior accuracy compared to the current standard measurement-while-drilling (MWD) surveys with in-field referencing and multi-station analysis (MSA).

In almost every drilling bottom hole assembly (BHA), there is an MWD survey tool to survey the wellbore while drilling. Accuracy of the MWD surveys has been improved over the years by correcting potential error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, limited global geomagnetic reference, and gravity model accuracy. This new positioning technique takes the accuracy of MWD surveys to the next level by combining surveys from two independent survey packages. The second survey package is installed inside the rotary steerable system (RSS). Surveys from both packages are retrieved while drilling.

Results have been obtained from multiple runs worldwide, enabling comparisons between the new technique and standard MWD surveys from both an enhanced accuracy and true wellbore placement point of view. A proposed error model is based on both the theoretical improvements in accuracy and the empirical proof from the data analyzed. The improved accuracy while drilling assures higher confidence that the well placement will maximize reservoir production and avoid collision with nearby offset wells.

In reservoir sections, the wellbore survey accuracy limits the lateral spacing, and this constrains the reservoir production. In top and intermediate sections, wellbore survey accuracy limits the well plan, and this affects how close the well can be drilled in proximity to other offset wells. This directly impacts the complexity of the directional work and the cost per drilled foot. The new technique unlocks the potential to significantly improve the wellbore positioning accuracy.

The scope of the paper is to explain, at first, the modification done to the conductor deck of a jack up rig in order to drill two exploration wells from one open water location, offshore of east coast of India. Further the paper explains the process of batch drilling used in the campaign and how the combination of the two resulted in substantial cost saving.

For the modification in conductor deck, feasibilities were checked for each rig during the tender evaluation stage to create an additional slot in the conductor deck while maintaining the conductor tensioning requirement on both slots. The conductor deck of the finalized rig was fabricated accordingly. The wells were planned, with one being vertical and the other deviated, to two different targets. The conductors on both wells were batch set. Similarly, the surface hole sections on both the wells were batch drilled & cased. Then drilling of the production holes, logging & abandonment were carried out batchwise.

As a result of batch drilling, the time in installation & removal of wellhead was completely saved as it was carried out offline. Similarly the time in installation & removal of BOP was reduced to half as it was done only once. There were other instances as well, described in detail in the paper, which led to a cumulative savings of 29.86 days against total planned time of 96.51 days during the complete drilling campaign, apart from saving days & associated weather risk by eliminating one complete rig move. Much of the time saved above was due to the batch drilling which was a result of the conductor deck modification and also due to the well design changes based on actual well conditions, which are also explained briefly in the paper.

As industry is recovering from a steep decline in drilling activity, it is only incremental innovations & even more so, a combination of existing innovations like the one showcased in this paper, which can lead to a positive economics for E&P companies, especially for exploration drilling projects.

Microbial contamination and extensive growth of bacteria in the drilling mud impact drilling operation and reservoir integrity. To reduce the damaging effect of microbial growth, drilling mud is generally treated with biocides for microbial control and preventing loss of rheological properties from biodegradation. Make-up water and drilling mud samples from reserve tank and mixing tank were collected from three drilling rigs in Saudi Aramco oilfields. The baseline number of general aerobic bacteria (GAB) and sulfate-reducing bacteria (SRB) in make-up water and drilling mud samples were determined using the Most Probable Number (MPN) method. Microbial growth in the drilling mud and microbial control using glutaraldehyde-based biocide were evaluated under the conditions simulating short-term (<24 hours) and long-term (up to 7 days) downtime of drilling operations. In short operational downtime, the current practice in Saudi Aramco with no biocide addition resulted in high number of GAB (105-107/ml) in the mud samples. In long operational downtime, addition of 1500 ppm of biocide (1/3 of normal dosage) at Day 3 was effective in controlling GAB and SRB growth in drilling mud. Biocide performance was significantly affected by sulfide content in the mud; higher dosage and more frequent treatment may be required to control the microbial growth in the drilling mud. The study indicated that biocide treatment is essential for microbial control in drilling operation, especially in the period of operational downtime. Finally, drilling mud operation and field best practice for microbial control were recommended to be implemented in all Saudi Aramco drilling rigs.

Dynamic effective stress (DES) is a consequence of a static and dynamic underbalance (UB) (Bell 1984) created when opening a lower-pressured wellbore by means of perforation to a higher-pressure formation to promote perforation cleanup, if intentional. It pertains to the brief, rapid rise in formation effective stress around the perforation tunnel walls immediately following detonation of tubing-conveyed perforating (TCP) guns. DES is the by-product of the dynamic UB commonly enhanced to surge debris out of the perforations with the rapid movement of pore fluid toward the wellbore (Bolchover and Walton 2006). In synchronization with the dynamic UB, the DES typically occurs for less than one second during the surge of pressurized formation fluid toward the 1-atm hollow-carrier perforating gun inside the cased wellbore. By understanding this mechanism, successful gravel packing may be achievable in a low-strength formation, displacing loose perforating debris with high permeability gravel. Important parameters that define the implication of dynamic UB are the same for DES and include formation pressure, shaped charge and gun characteristics, and formation rock and fluid properties. During advanced American Petroleum Institute Recommended Practice 19B Section 2/4 laboratory (API RP 19B 2014) for perforator performance testing, these parameters can be matched at pressures and temperatures where dynamic UB and DES effects are prevalent. By conducting multiple tests adjusting the free gun void space, wellbore volume, the type and size of the shaped charges, and the formation target from low-strength to moderate-strength, observations can be analyzed and quantified.

It has been observed that when perforating in weak rock with less than 1,000-psi unconfined compressive strength (UCS), even the smallest DES increase with associated dynamic UB flow can result in a collapsed tunnel or filled-in cavity, as viewed in computed tomography (CT) scan images. Conversely, perforation tunnels in rocks with higher UCS have been observed to withstand collapse when subjected to a high DES and dynamic UB. The variance of rock strength and differences in shaped-charge design determine the maximum DES and dynamic UB that are tolerable in a specific wellbore-matched configuration. Another observation is that the viability of the perforation tunnel depends heavily on the size of the exit hole diameter created in the casing. Large, big hole (BH) charges creating upward of 1-in. diameter holes in the casing require larger-diameter rock targets for testing when using the weaker, high-flow-capacity reservoir-analog rocks. Standard 7-in. diameter rock targets appear to be adequate for testing tunnel collapse on the largest deep penetrating (DP) charge if pore pressures do not exceed 12,000 psi. In addition, oil vs. water pore space fluid shows slightly more resistance to perforation tunnel collapse. The identification of the conditions for preserving a tunnel during the perforating process is important for the success of subsequent steps in the completion process, such as gravel packing or stimulating. Performing customized API RP 19B Section 2/4 testing at the unique conditions of the specific well in question helps completion engineers to select the best perforating technique.

De-completing wells -- due to downhole problems related to tubing-casing annulus communication, casing
leaks or prior to executing reentry sidetracks for multilateral wells -- is adaily activity in the oilfield
business. Conventional completions comprised of downhole production packers and tubing are normally
retrieved with no major issues. But this is not the case for intelligent completions, as they include a numberof
downhole components that makes its retrieval more challenging, and there was no set procedure or provision
in place to retrieve them, in case of failure or encountered downhole problems during the production life
of the well. Since intelligent completion deployments are increasing, the number of intelligent wells to be decompleted
will also increase. This paper presents the case history and experience gained during the de-completion of intelligent
completions of different designs; highlights the challenges and difficulties in recovering of multiple packers
and flow control valves; and the strategy to achieve full access to the wellbore, to reestablish production and
recover assets. This paper will also summarize lessons to achieve successful de-completion of an intelligent
well.

Thermal rheological properties of three drilling fluids suggested for hot environments were experimentally investigated using both HTHP dynamic rheometer and classical viscometer. Two of them were polymer based muds commercially used in geothermal drilling, and the third one was sepiolite base mud prepared with specially mixing order in this study. Rheological measurements at six different shear rates were performed in a programmed temperature range of 100 to 500°F with 10°F increments at a 700 psi of pressure differential. Flow characteristics of sample muds in a given well geometry were also considered using a numerical application.

Two polymeric muds sampled from a geothermal field in Turkey exhibited very low viscosity with a low thermal viscosity variation interval at temperatures above 300°F. In contrary, the sepiolite mud demonstrated higher viscosity and kept its stability with increasing temperatures up to 500°F. Findings also indicated remarkable viscosity differences between the conventional viscometer and the dynamic HTHP rheometer. Hydraulic optimization in terms of circulation pressure losses, cutting transport, and surge and swab pressures were numerically modelled. Optimization results based on conventional viscometer measurements generated noticeable errors causing difficulties through drilling program. Numerical application revealed that the usage of improper viscosity values resulted in calculation of well design parameters beyond the safe drilling limits.

Through this study, it was revealed that sepiolite based muds could be good candidate for drilling hot and/or hostile wells such as deep oil and gas wells, geothermal wells, and drilling through high saline formations. As excessive temperature through wellbore can lead to serious well problems, selecting thermally stable mud with proper rheological properties to improve penetration rates, hole cleaning properties, and borehole integrity can clearly express the importance of this study.